歐尼克 (OKE) 2013 Q3 法說會逐字稿

Good day and welcome to the third-quarter 2013 ONEOK and ONEOK Partners earnings call. Today's conference is being recorded. At this time I would like to turn the conference over to Mr. Andrew Ziola. Please go ahead, sir.

Thank you very much and welcome to our third-quarter 2013 earnings conference call. A reminder that statements made during this call that might include ONEOK or ONEOK Partners' expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provision of the Securities acts of 1933 and 1934. Actual results could differ materially from those projected in any forward-looking statement. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings.

Before we begin a brief announcement, the ONEOK, ONEOK Partners, ONE Gas investor day is scheduled for Tuesday, December 3 in New York. A save the date notice was sent last week and we'll be following up with webcast information in a couple of weeks. With that our first speaker is John Gibson, Chairman and CEO of ONEOK and ONEOK Partners. John.

Thanks, Andrew, thank you, good morning. Many thanks for joining us today. As always, we appreciate your continued interest and investment in ONEOK and ONEOK Partners. Joining me on the call today are Derek Reiners, our Chief Financial Officer, and Terry Spencer, our President. Also on the call and available to answer your questions are Pierce Norton, our Executive Vice President Commercial, and Rob Martinovich, our Executive Vice President of Operations.

On this morning's call we will review our third-quarter 2013 financial results, review our updated 2013 guidance ranges, discuss the acquisition of the Sage Creek assets and discuss the current status and key milestones of the ONE Gas separation. Let's get started with our third-quarter performance.

ONEOK's third-quarter performance was driven by continued volume growth in ONEOK Partners, with volume increases in natural gas gathered and processed and natural gas liquids gathered as a result of the growth projects that we have completed.

At ONEOK Partners our NGL exchange services margins increased compared with the same period in 2012 as we continued to execute our strategy to convert capacity held for optimization activities to fee-based contracts. As a result and as expected, our optimization margins declined as a result of this reduced capacity and the expected tighter NGL price differentials experienced between Mont Belvieu and Conway.

Also as anticipated, ethane rejection had some impact on our third-quarter results. However, it was less than $11 million and does not include the positive impact of minimum volume obligation.

Our natural gas distribution segment performed well during the quarter benefiting from new rates in all three of the states it serves. Energy services results were a bit higher than expected due to the release and/or the assignment of certain transportation and storage contracts at higher rates than we initially assumed.

As we typically do this time of the year, we have updated our net income guidance range for ONEOK and net income and distributable cash flow range for ONEOK Partners. As Andrew mentioned at our investor day in New York on December 3, we intend to provide 2014 guidance and updated three-year financial forecasts for ONEOK, ONEOK Partners and ONE Gas.

At this time Derek will now review ONEOK's financial highlights, followed by Terry who will review ONEOK's operating performance. Derek?

thanks, John, and good morning. ONEOK's third-quarter net income was approximately $62 million, or $0.30 per diluted share, including a non-cash charge as expected from the release of transportation capacity related to the accelerated wind down of the energy services segment.

ONEOK's net income in the third quarter 2013 would have been approximately $73 million, or $0.35 per diluted share, excluding the impact of the non-cash charge, compared with $65 million or $0.31 per diluted share for the third quarter of 2012.

In the third quarter of 2013 energy services recorded a $16 million pretax non-cash charge which for the nine-month 2013 period totaled $130 million related to the capacity releases executed in 2013 for certain transportation and storage contracts. These charges were lower than we initially estimated as we received higher rates on some contracts compared with our original estimates.

During the third quarter 2013 this segment paid approximately $6 million in cash related to these obligations. We expect future cash payments associated with the released transportation and storage capacity from the wind down to total approximately $89 million on an after-tax basis, with approximately $8 million to be paid in the fourth quarter of 2013, $33 million in 2014, $24 million in 2015 and $24 million over the period 2016 through 2023.

In the first nine months of 2013 ONEOK received approximately $397 million in distributions from ONEOK Partners, a 27% increase from the same period last year. ONEOK's year-to-date 2013 standalone cash flow before changes in working capital exceeded standalone capital expenditures and dividend payments by $117 million. In October we declared a dividend of $0.38 per share, unchanged from the previous quarter.

As John mentioned, we did update ONEOK's 2013 net income guidance range, now expected to be in the range of $245 million to $275 million compared with $235 million to $285 million. The midpoint remains the same reflecting the lower than anticipated non-cash charges in the energy services business offset by lower anticipated earnings in the partnership's natural gas liquids segment.

ONEOK's balance sheet and liquidity position remains solid. At the end of the third quarter on a standalone basis we had $515 million of commercial paper outstanding, $57 million of cash and cash equivalents and $683 million available under our $1.2 billion revolving credit facility. Our standalone long-term debt to capitalization ratio was 44%.

At ONEOK's investor day we will provide new dividend growth rate expectations at ONEOK. And as previously discussed, we expect the growth in ONEOK's dividend to be competitive with its pure play general partner peers. The new dividend, which is subject to Board approval, is expected to be declared in the quarter after the ONE Gas transaction is completed. So, if the separation occurs in the first quarter of 2014, as we anticipate, we would expect to declare the new dividend in April.

Additionally, ONE Gas will provide its expected initial dividend -- dividend growth rate expectations and payout ratio range. We also expect to share our thoughts on how to think about the dividend and liquidity needs at ONEOK post separation. Now Terry will update you on ONEOK's operating performance.

Thank you, Derek, and good morning, everyone. Let's start with our natural gas distribution segment. Third-quarter 2013 earnings were higher primarily reflecting higher rates in Oklahoma, Kansas and Texas. Operating costs were slightly higher compared with the third quarter 2012 primarily because of higher pension expenses which were partially offset by lower share-based compensation expense.

As Derek discussed, the energy services segment incurred a lower-than-expected non-cash charge related to the release capacity in the third quarter. Excluding that charge net margin increased by approximately $11 million in the segment compared with the same period last year, primarily due to lower demand charge costs in the third quarter 2013 resulting from reduced contracted transportation and storage capacity. John, that concludes my remarks for ONEOK.

Thank you, Terry. Now Derek will reveal ONEOK Partners' financial performance and then Terry will come back and review the partnership's operating performance, growth projects and discuss the Sage Creek acquisition.

Thanks, John. In the third quarter ONEOK Partners' net income was approximately $216 million or $0.64 per unit compared with $232 million or $0.78 per unit in the third quarter of 2012.

Distributable cash flow was $259 million in the quarter compared with $261 million in the third quarter of 2012 resulting in a coverage ratio of 1.14 times for the third quarter of 2013. Distributable cash flow was $704 million for the first nine months of 2013 providing a 1.04 times coverage compared with $781 million for the same period last year.

Our long-term annual coverage ratio target remains at 1.05 to 1.15 times. However, as discussed in previous conference calls, we expect our full-year 2013 to be slightly above one times coverage.

In August we completed a public offering of 11.5 million common units which generated proceeds of $553 million. In September we completed a $1.25 billion public offering of senior notes generating net proceeds of approximately $1.24 billion. Proceeds from these two offerings provide significant capacity for our capital expenditures program.

We now expect ONEOK Partners' 2013 net income to be in the range of $790 million to $830 million compared with the previous range of $790 million to $870 million. The new range reflects lower anticipated earnings in our NGL segment due to narrower NGL location price differentials. The partnership's DCF is now expected in the range of $930 million to $980 million compared with its previous range of $910 million to $1 billion. The midpoint remains at $955 million.

An update on our 2013 growth capital forecast to $2 billion from approximately $2.2 billion and reduced our maintenance capital to $100 million from $120 million for 2013 primarily due to timing. This does not impact our $5.3 billion to $5.6 billion growth program. We increased the distribution declared by $0.005 per unit to $0.725 in the third quarter of 2013, an increase of 6% from the third quarter of 2012.

In the earnings release you'll note some updates in our hedging information as we continue to hedge commodity risk when appropriate. At the end of the third quarter the partnership had $723 million of cash and cash equivalents, $47 million in commercial paper and approximately $1.2 billion of credit available to us on our revolving credit facility.

Our long-term debt to capitalization ratio was 55% and our debt to adjusted EBITDA ratio was 4.2 times. We have ample liquidity to support the partnership's ongoing capital program.

In regards to our at the market equity program, we took a conservative approach by not selling units while ONEOK was evaluating the ONE Gas separation and we were blacked out for most of the third quarter due to our August equity issuance. We do expect to utilize this program in the future when conditions warrant as a way to manage our equity issuances over time. Now Terry will update you on the partnerships' operating performance.

Thank you, Derek. Natural gas gathering and processing segment's third-quarter operating income was higher due primarily to higher natural gas volumes gathered and processed, offset partially by lower realized NGL prices and higher operating costs and depreciation expense due to the growth projects we placed in service over the last year.

Natural gas volumes gathered and processed continue to grow driven by increased well connections in the Williston Basin and Western Oklahoma. For the third quarter natural gas volumes gathered increased 21%, natural gas volumes processed increased 25%, and NGLs sold increased 34% compared with the same period last year, driven by the Williston Basin's new Garden Creek and Stateline I and II natural gas processing plant and related infrastructure projects completed in 2012 and in 2013.

We connected 340 wells in the third quarter, our highest ever, and 950 September year to date compared with 710 wells last year through September. We now expect to connect approximately 1,200 wells to our Williston Basin and the Mid-Continent gathering systems in 2013. Accordingly, we remain confident in our volume expectations we provided on our last earnings call.

Our natural gas liquid segment's third-quarter results were lower due to significantly narrower Conway-to-Mont Belvieu NGL price differentials and the impact of ethane rejection. As expected, NGL exchange services margins and NGL gathered continued to grow while NGL optimization margins decreased compared with the same period last year as a result of ONEOK Partners' strategy to convert NGL optimization capacity to fee-based exchange services capacity that partially offset the impact of narrower Conway-to-Mont Belvieu differentials. Our integrated NGL system also enabled us to capture higher margins from wider NGL product price differentials.

From a volume perspective, NGLs transported on gathering lines were 574,000 barrels per day in the third quarter, 2013, up 8% compared with the same period last year and up 4% compared with the second quarter 2013. As in the G&P segment, we remain confident in the NGL segment's volume expectations we provided on our last earnings call.

Ethane rejection did result in NGL pipeline capacity typically utilized for exchange services business becoming available for optimization activity, allowing us to benefit somewhat from NGL price differentials that are still relatively narrow compared to the five-year average between the Mid-Continent and Gulf Coast NGL market centers.

The natural gas pipeline segment third-quarter financial results were slightly higher compared to the same period in 2012. Equity earnings from Northern Border Pipeline were lower in the third quarter 2013 due to reduced transportation rates on Northern Border Pipeline. Substantially all of Northern Border Pipeline's long-haul transportation capacity has now been contracted through March, 2015.

Now an update on our projects. We have several projects expected to be completed in the coming months. The MB-2 NGL fractionator at Mont Belvieu is expected to be in service this month and the Sterling III Pipeline is expected to be completed by the end of this year with the flexibility to transport either unfractionated NGLs or NGL purity products from the Mid-Continent region to the Texas Gulf Coast.

By the end of this year we will have spent approximately $130 million for the Divide County natural gas gathering system project in North Dakota. The remaining $20 million of additional expansion for this project will be spent throughout 2014 to complete the remaining infrastructure.

Last month we completed the acquisition of the Sage Creek asset, which include a 50 million cubic feet per day natural gas processing plant and NGL pipeline system in the NGL rich area of the Powder River basin. We also plan to invest additional capital to upgrade and construct natural gas gathering and processing related infrastructure and well connections and NGL gathering pipelines which will connect to Sage Creek and third-party processing plants, including a lateral to our NGL Pipeline in the Bakken NGL pipeline.

This acquisition provides significant long-term growth potential in the basin and the opportunity to provide area producers and processors with a full menu of midstream natural gas and NGL-related services.

Now a brief look at the NGL markets. We have not changed our outlook for ethane rejection for 2014 and 2015. We still believe that ethane rejection by natural gas processing plants connected to our NGL system will continue at current levels of approximately 90,000 barrels per day throughout much of 2014, and through 2015 but primarily in the Rockies.

Gulf Coast and Conway NGL inventory levels, especially for ethane and propane, are decreasing as ethane rejection continues and due to strong export demand for propane. From a demand perspective with major plant outages behind them the petchems are consuming the excess ethane inventory and we expect a significant drawdown throughout the remainder of this year and into 2014.

The petchems are operating at high utilization rates with ethane as their primary feedstock and we see no signs of that slowing down. Additionally, some petchems who have been using propane as a feedstock have over the past few months switched back to ethane which we estimate to be 50,000 to 75,000 barrels per day. From a pricing perspective this should lead to some upside momentum to ethane prices. But we expect it will be slow and moderated by the ability of processors to recover ethane fairly quickly and rebalance the market.

Propane inventories are decreasing in both Conway and Mont Belvieu from extensive seasonal demand from crop drying in the upper Midwest and from strong export demand. In recent weeks we have seen the Conway-to-Mont Belvieu ethane price differentials range from $0.03 to $0.06 per gallon and we expect this range to continue for the rest of this year.

While we recognize the continued near-term challenges regarding excess ethane supply, the partnership remains well-positioned through its integrated network of assets and NGL rich basins to provide essential services to its customers for the long-term. John, that concludes my remarks.

Thank you, Terry. Now let me provide you with an update on the status and the timeline of the ONE Gas separation. All of those involved have made remarkable progress to complete the necessary filings required for the separation, which include of course the Form 10, the New York Stock Exchange listing materials, the IRS and the FERC filings and completing and updating the filings with the Kansas Corporation Commission and related parties.

Our discussions with the KCC have been very productive and collaborative. Last week the KCC released a procedural schedule for the order setting process. There are two possible tracks for approval. The first proposes a settlement agreement with all parties designed to be sent to the KCC for approval by the end of 2013. And the second, if the parties are unable to reach a settlement, would result in KCC approval in late February.

We are confident that our discussions with the KCC and other parties will continue to be productive and we still expect to complete the separation in the first quarter of 2014. Upon the KCC approval we estimate the transaction will close within four to five weeks thereafter.

In closing, I would like to again thank our 5,000 employees whose commitment, dedication, skills and experience allow us to operate our assets safely, reliably and environmentally responsibly every day and to create exceptional value for our investors and our customers. Our entire management team appreciates all of our employees' efforts to make our Company successful. So at this time we are now ready to take your questions. Thank you.

(Operator Instructions). Ted Durbin, Goldman Sachs.

Just wanted to check on the Sage Creek acquisition, maybe I missed this. But what is the run rate EBITDA on the existing assets? And then what are the volume assumptions that you are making to get to the -- I think it is $40 million to $60 million of incremental EBITDA?

Well, Ted, we actually don't provide that specificity publicly, okay, as far as what our volume forecasts are. But what I can tell you is that the EBITDA estimate that we provided when we announced the project is really just kind of a Phase 1, if you will, okay. But there are going to be additional projects which we kind of refer to as a Phase 2.

So we will see some significant increase in the EBITDA there. Much of that is driven not only by increased gathering and processing revenues, but in particular NGL-related revenues associated with the natural gas liquids that will connect into the Bakken pipeline.

So, Ted, I think it is safe to say that the opportunity in buying those assets was for future development; we didn't look at that as an opportunity to buy earnings as much as it was to buy future earnings.

Yes, John, that is great. The only thing I would add to that is that one of the key components in the acquisition were the substantial acreage dedications that went with it.

Great, got it. Okay, that is helpful. And then if we can talk about the Bakken maybe again, how you are seeing that shape up with where production seems like it has kind of reaccelerated, the need for additional processing plants, gathering infrastructure, kind of where your acreage dedications are, if you see the need for that. And then if you could talk about your contracting strategy up there. I think you have mostly gone POP, but would you maybe try to go fee based on anything, any future development?

Ted, development continues to be very strong, particularly with the multi-pad drilling that is going on. So the producers are really able to complete a lot of wells quickly. So the production, as you have probably seen publicly -- in public -- people who follow the Bakken production is going off the chart. So we expect to continue to make investments as it relates to gathering and processing infrastructure. Now I've forgotten the last part of your question.

Just the contracting strategy, would you look to stay more POP? I think your acreage dedication would lead you there, but would you try to make that more fee-based or how are you thinking about that?

We already have fee-based components in our contracts. They are a mix of POP and fee-based. Don't anticipate changing it because that strategy has worked real well for us.

I might add one of the reasons that strategy has worked so well is that is what the producer wants. So that is kind of a natural.

That mutual alignment up here has worked extremely well when both parties make more money. When prices are up both parties make more money at the same time. So we really don't anticipate changing the contracting strategy, Ted.

Got it. And then the last one for me just on the maintenance CapEx, I did see it came down for this year. How should we think about sort of more of a run rate for maintenance CapEx as we are thinking about into 2014 and 2015?

Yes, Ted, we have been in that 100 to -- over our history last couple of years been in that $100 million to $120 million run rate range. Going forward, it will increase somewhat, slightly certainly as we (technical difficulty) the assets that we have on our books. I think the thing that you have got to think about as it relates to this maintenance capital about 20% to 25% of that maintenance capital are discretionary types of items.

So they are noncritical types of maintenance capital like clearing rights-of-way, paving parking lots, things like that. So they are noncritical items. And so, we have the ability to defer those depending upon what our work priorities are. So you can see that number fluctuate from year to year. And most of the time it is attributable to these discretionary items I just mentioned. Does that help you?

That is very helpful, thanks. That is all I have. Thank you, guys.

Chris Sighinolfi, Jefferies.

Just a quick question on price realizations in the G&P segment. It seems like there has been some weakness this year relative to NYMEX realizations and also the hedge prices. So I am just curious what is going on there, Terry, in the Mid-Con and specifically with your G&P operations that is driving that? And if those conditions are likely to change in coming periods?

Yes, that is a great question, Chris. We had -- in the third quarter had a bit of an anomaly where the prices we realized for the unhedged volumes were very low due to basis disconnect in the Bakken. The ACO prices had really gotten beaten pretty hard and the trickle back effect to the Bakken, we saw some dollar discounts between the Bakken and the market area. So that affected us and affected that pricing in the third quarter and that is the primary reason for that spread -- that disconnect, if you will.

Okay, and how do you see that sort of progressing as we move forward in time, Terry? Obviously Ted was asking about growth from that basin, but from the gas side then how do you think about pricing disconnects on a go forward?

I think it is resolving -- that issue is resolving itself. It is not really a problem today but it is there as volumes -- Canadian volumes continue to grow. As Marcellus gas backs up in the Midwest that is going to impact us somewhat. So you are going to still see some pricing disconnects.

Okay. I think switching gears a little bit; I appreciate your NGL market color update on your views. I'm just curious what you are anticipating for your pads two and three processing and frac assets given the pending in service at [Apex].

And then I guess related to that, Terry, we have a couple wide grade lines proposed down to the Gulf Coast region, one of which seems to require some downstream fractionation. We have seen some of the other Belvieu peers announce plans to pursue permits on some incremental fractionation capacity there. Just interested to know post MB-2 what else sort of remains in the backlog that you might be working on to accommodate that pipe should it come?

Well, certainly with the pipelines that are being built into the region, some of them are not being built with companion fractionation capacity. So the opportunity exists for us to potentially provide more fractionation services, to provide storage services and infrastructure services for those parties that do construct or build those pipelines or ship through those pipelines.

So I think there is going to be opportunity for us without necessarily having to own and operate a pipeline all the way back to the basin. As far as the impact from those projects you talked about, one in particular, Texas Express, coming out of the Panhandle area down to the Gulf Coast, that pipeline has started up and we have already seen some impact from that in the Conway prices. As they started that pipeline up and accumulated line fill we did see some pressure. So those pipelines are going to impact the market somewhat.

Okay. I think final question for me, Terry, given Ted's question about growth from the Bakken, obviously you've got a lot of shadow growth projects still out there and you have had an appetite in the past to pursue some crude oil infrastructure project. I'm just wondering what sort of the conversation has been like recently with potential counterparties on some of the shadow inventory given where pricing spreads have gone. Has there been a change in that dynamic and in those conversations?

Well, certainly they don't disregard the market; they look and see what is going on. The bottom line is they still -- many of our customers, want to get to Belvieu, it is where the most liquid market is. And they understand there is a cost; regardless of the basis spread between Conway and Belvieu there is a cost associated with getting -- building and operating this infrastructure. So they are willing to pay the freight and are stepping up and paying the freight.

And so, we are continuing to execute on and develop opportunity for new supply, and in particular crude oil -- as it relates to crude oil. We have seen that basis spread, that East Coast basis spread compress. Now it has widened back out, okay, so it is very volatile. And we've seen producers want to continue to discuss the possibility of a pipeline asset in particular out of the Bakken all the way down to Cushing.

But, as you might not be surprised, those producers still remain hesitant to make the types of commitments that is necessary, at least for our capital, to make a project like that work.

Okay, great. Thanks, guys. Look forward to seeing you next month.

John Edwards, Credit Suisse.

Just could you -- I don't know if I saw it, but the in-service date for the expansion that you are doing around your Sage Creek acquisition.

Yes, 2015 was the timeframe. You are talking about the lateral that was (multiple speakers)?

Yes, the $135 million one you just announced with this release.

Yes, exactly. That consists of two things -- or actually three things primarily, a $50 million expansion of the processing facility, or a modification to the processing facility to allow it to handle extremely rich gas that is being produced out of this play. The rest is the pipeline to interconnect the assets to the Bakken, plus another pipeline lateral to connect it to a third party processing plant.

Okay, you are looking first half or second half of 2015?

Actually you are right around the end of 2014, perhaps early 2015.

Okay, got you, all right. And then I just want to make sure I heard you right. Your expectations on the Conway Belvieu spread in NGLs you are looking at $0.03 to $0.06 a gallon, is that the thought process?

That is the range that we expect.

Okay. And then in terms of going further out, are you still looking for that range say for 2014 and 2015?

Well, we are looking at something probably a little higher, maybe $0.06 to $0.07 going forward for EP.

Okay.

We think the ethane inventory overhang is one of those key things that has affected the spread. And certainly we've seen it affect it here in the fourth quarter. But as we move through this fourth quarter and into the second quarter we and many of the experts expect this ethane inventory overhang to be substantially resolved.

Right, yes, okay. Okay, great. That is actually all I had. Thank you.

Christine Cho, Barclays.

I know the answer for this may be that it is contract specific, but at a high level can you give us some color around the older plants that may not be that efficient in extracting out ethane? Does the customer have a daily, weekly or monthly option to reject ethane?

No, they do not. They don't. They really cannot drive our operations.

Meaning you guys pick?

That is correct.

I see, okay. And then have you contracted capacity on the Bakken NGL line? Are any of your other NGL distribution or gathering lines on a ship or pay basis for your equity barrels? Or is it more based on actual volume shipped? How do we think about that?

Well, most of the capacity on these new projects, and the Bakken pipeline included, most of these are on a ship or pay basis, okay?

So, even for your equity barrels?

Yes.

And then when you contracted it, I mean it was over a year ago, did you only take enough capacity for propane plus volumes or did you include ethane in it too?

Some ethane has been included in that.

Okay, and then in the NGL segment you mentioned operational measurement gains. Can you remind us what that exactly is? And then also when you say higher revenues from customers with minimum volume obligations, does this mean they have to pay some penalty for not meeting minimum volume?

Okay let's take this -- that is a bunch of questions, so -- and I guarantee you I won't remember them all. But let me take the first one telling you what operational measurement gains are. It relates to measurements -- inherent in NGL or natural gas measurement you have some inaccuracy, okay, plus or minus less than a percent in most cases. That is what that is. And from time to time we will have periods where we have gains in the system or losses, okay. So that is what that is referring to.

Okay.

Okay? Then your next question was --?

You guys point out that you had higher revenues from customers with minimum volume obligations. I was just curious if that meant that they have to pay some penalty for not meeting minimum volume?

That is correct. In the MVA type contracts that we have there is a penalty payment that they have to make if they are deficient or sometimes we call the deficiency payments that they have to make.

Okay, and then at distribution are you guys tracking better than expected or is there something -- some timing-related differences in 4Q that would cause full-year operating income numbers to come in around the $227 million number that you have previously guided towards?

Christine, this is Pierce. We are tracking on plan. If you will notice kind of the year over year is more some pension-related costs. But we are tracking where we expect to be.

Okay, great. Thank you.

And that concludes our question-and-answer session. I will turn the call back to our speakers for any further remarks.

Well, thank you for joining us, everybody. Our quiet period for the fourth quarter starts when we close our books in early January and extends until earnings are released after the market closes on February 24 followed by our conference call on February 25. We will provide details on the conference call at a later date. T.D. Euresti and I will be available throughout the day to answer any follow-up questions you may have. Thank you, and have a good day.

Ladies and gentlemen, this does conclude today's teleconference. We thank you for your participation.